In-bit strain measurement for automated bha control

ABSTRACT

A bottom hole assembly of a drilling apparatus is configured for drilling a borehole through a formation, the bottom hole assembly comprising a drill bit assembly coupled to one or more bottom hole devices, wherein the drill bit assembly comprises one or more sensors located within the drill bit assembly, and wherein the one or more bottom hole devices comprises a controller configured to receive one or more sensor output signals, and to control one or more parameters of the drilling operations based at least in part on the received sensor output signals.

TECHNICAL FIELD

This disclosure relates generally to drilling operations used to form a wellbore.

BACKGROUND

Hydrocarbons, such as oil and gas, are commonly obtained from subterranean formations that may be located onshore or offshore. The development of subterranean operations and the processes involved in removing hydrocarbons from a subterranean formation are complex. Typically, subterranean operations involve a number of different phases, such as, for example, drilling a wellbore at a desired well site, cementing the well, treating the wellbore to optimize production of hydrocarbons, and producing and processing the hydrocarbons from the subterranean formation for downstream use.

To obtain hydrocarbons such as oil and gas, boreholes are drilled by rotating a drill bit attached at a drill string end. A proportion of the current drilling activity involves directional drilling (e.g., drilling deviated and/or horizontal boreholes) to steer a well towards a target zone and increase hydrocarbon production from subterranean formations. Modem directional drilling systems generally employ a drill string having a bottom-hole assembly (BHA) and a drill bit situated at an end thereof that may be rotated by rotating the drill string from the surface, using a mud motor arranged downhole near the drill bit, or a combination of the mud motor and rotation of the drill string from the surface.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the disclosure may be better understood by referencing the accompanying drawings.

FIG. 1 is a diagram of an illustrative well system, according to various embodiments.

FIG. 2A depicts a functional block diagram of a bottom hole assembly, according to various embodiments.

FIG. 2B depicts a functional block diagram of one or more bottom hole assemblies, according to various embodiments.

FIG. 3 illustrates a flowchart of a method, according to various embodiments.

FIG. 4 illustrates a block diagram of an example computing system 400 that may be employed to practice the concepts, methods, and techniques disclosed herein, and variations thereof.

The drawings are provided for the purpose of illustrating example embodiments. The scope of the claims and of the disclosure are not necessarily limited to the systems, apparatus, methods, or techniques, or any arrangements thereof, as illustrated in these figures. In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same or coordinated reference numerals. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness.

DETAILED DESCRIPTION

In the following detailed description of the illustrative embodiments, reference is made to the accompanying drawings that form a part hereof. The description that follows includes example systems, methods, techniques, and program flows that embody embodiments of the disclosure. These embodiments are described in sufficient detail to enable those skilled in the art to practice the techniques and methods described herein, and it is understood that other embodiments may be utilized and that logical structural, mechanical, electrical, and chemical changes may be made without departing from the scope of the disclosure. To avoid detail not necessary to enable those skilled in the art to practice the embodiments described herein, the description may omit certain information known to those skilled in the art. The following detailed description is, therefore, not to be taken in a limiting sense.

The embodiments described herein relate to systems, apparatus, methods, and techniques that may be used to provide in-bit strain measurements using one or more sensors located within a drill bit assembly of a bottom hole assembly configured for drilling a borehole through subterranean formation material. The in-bit strain measurements may then be provided, in real time or near real time, to one or more components included in a system or apparatus performing the drilling operation. In various embodiments, these components include a rotary steerable system (RSS) that is provided as part of the bottom hole assembly or integrated into the bit. The rotary steerable system may include one or more processing devices that are configured to receive outputs signals from the one or more sensors located within the drill bit assembly, to process these received output signals, and to provide control output signals, in real-time or near real-time, to one or more actuator devices included in the rotary steerable system. Other devices, which may or may not be associated with the steering of the drilling operation, may be included as part of a bottom hole assembly of a drill bit string, and may be controlled, at least in part, based on the measurements made by the sensor(s) located within the drill bit assembly, as further described below.

As used in this disclosure, the terms “real time” and “near real time” or “real-time” and “near real-time” refer to the time period required for a device, such as a computer processor, to process data inputs and generate and output, such as additional data and/or output signals, based on the processed data. In various embodiments, the data inputs may include the output signals provided by the one or more sensors located in a drill bit assembly, and the output signals may include a status indication or indication(s) related to a drilling operation and/or control signals for adjusting one or more parameters associated with the drilling operation being performed by the bottom hole assembly where the one or more sensors are located. In various embodiments, the output signals generated might include messages, alarms, or other types of outputs directed to a user, such as a field technician or engineer, which require an input or other type of response from the user. In such instances, the delay between outputting the request for the user input and receiving a response from the user is not considered part of the real time or near real time period.

In various embodiments, the one or more actuator devices are configured to include controllable mechanical mechanisms that may be actuated, based on the control output signals, to direct the steering of the drill bit assembly as the drill bit is operated to advance a borehole along a desired trajectory or path through the formation material. In various embodiments, the one or more components receiving the in-bit strain measurements, or the data associated with or derived at least in part from the in-bit measurements, may include devices located remotely relative to the drill bit assembly, such as devices located on the surface. These remotely located devices may include computer controlled devices and/or manually controlled devices that are configured to both confirm the proper operation of the drilling operation being performed by the drill bit and/or RSS to provide for adjustments to one or more parameters associated with the drilling operation, the confirmation and/or adjustments provided in real time or near real time and based at least in part of the in-bit measurements and/or RSS or data derived at least in part from these in-bit strain measurements and/or RSS and/or MWD strain measurements.

While drilling a well, multiple parameters are be controlled to achieve desired steering performance. As drilling conditions can be different than forecasted, feedback systems are used to assess performance with respect to the original plan, and parameters of the drilling operation are routinely adjusted to achieve desired performance.

In most traditional setups the tools/bottom hole assembly is setup, and then drilling can commence to between 10-30′ before any data is returned that provides feedback on steering performance which is typically measured by dog leg severity (DLS) achieved. This procedure generates a latency in feedback that limits the ability to respond immediately to conditions where DLS is different than what was predicted. Conditions that could lead to such deviation from expected performance could be improperly functioning tools, tool wear, hole washouts, different formation than expected, too high of rate-of-penetration (ROP) to yield DLS for the given formation, and/or unexpected formation push tendency etc. Working with this sort of latency could lead to the well not meeting plan, or to slow down drilling to allow for additional parameter changes or tool adjustments. All of these additional changes can lead to additional cost to drill the well or in some cases require abandonment of a well section.

One of the feedback systems used by traditional push-the-bit RSS (mud or sealed oil) systems that has a reduced latency is the pressure difference across the steering pads to establish that the RSS is working as expected. However, this does not take into account effects such as hole enlargement, reduced bit side cutting force due to formation contact points on the bottom hole assembly, etc. Directly measuring the weight-on-bit (WOB), bending-on-bit (BOB), and the torque-on-bit (TOB) using sensor located within the bit or bit assembly allows for direct measurement of the bit reactionary forces applied as a result of the various steering pad actuations. This in turn can give a superior feedback on steering performance than pressure across the pads.

Embodiments as described herein employ direct measurements at the drill bit, and automated use of the data provided by those measurements, to improve service quality and performance reliability with respect to the drilling operation. The ability to measure at-bit strain directly at the drill bit assembly, and to input those measurements in real-time or near real-time into automated drilling algorithms operated by a controller located downhole in the rotary steerable system, or by other components located for example at the surface, will allow for a feedback loop that directly measures the applied bending/torque/weight on the bit when the duty cycle or steering force is adjusted in the RSS control systems or other operating parameters are adjusted for example by components located remotely from the drill bit assembly. Proper measurement of this facilitates a tailored selection of parameters to ensure staying on plan when in the curve—where the parameters include, but are not limited to duty cycle, WOB, RPM and flow rates of drilling mud. This real time response could be developed in downhole electronics for automated cruise curve control, or alternatively could be done on surface computer when this measurement or equivalent is pulsed up to a device located at the surface. Embodiments of the systems, apparatus, method and techniques as described herein may work well in a variety of drilling scenarios, including:

-   -   in drilling a low DLS well which covers over 90% of the market         where monitoring multiple inclination measurements in a BHA is         not an option;     -   for monitoring the curve downhole for cruise curve control,         (this will be an excellent proxy for automated curve control);         and     -   for producing a smoother wellbore, less torque and drag, and to         provide an overall improved quality for both the drilling and         completions processes in all well sections, especially extended         tangent & amp and/or laterals intervals.

FIG. 1 is a diagram of an illustrative well system 10, according to various embodiments. In one or more embodiments, the well system 10 may be a hydrocarbon recovery, exploration, production or services environment. Well system 10 may comprise a drilling rig (or derrick) 22 positioned on surface 16, and used to extend a tubing string 30 into and through one or more portions of a subterranean earthen formation 14. While FIG. 1 illustrates an on-shore well system 10, the present disclosure contemplates that the embodiments may be implemented off-shore for a subsea drilling operation.

The tubing string 30 may be disposed, positioned or lowered in a wellbore 12. Tubing string 30 may carry a drill bit 102 at a distal end of the tubing string, which may be rotated to drill through the formation 14. A drilling fluid 32 may be injected, pumped or otherwise disposed within the wellbore 12 to facilitate the drilling of the wellbore 12. Drilling fluid 32 may be any type of downhole fluid used in drilling, for example, a mud-based fluid. Formation 14 may be a subterranean formation or a subsea formation. A bottom hole assembly (BHA) 101 interconnected in the tubing string 30 proximate the drill bit 102 may comprise one or more components and assemblies (not expressly illustrated in FIG. 1 ), such as, but not limited to, logging while drilling (LWD) equipment, measurement while drilling (MWD) equipment, a bent sub or housing, a mud motor, a near bit reamer, stabilizers, steering assemblies, and other downhole instruments, tools or assemblies. The BHA 101 may also comprise a rotary steerable drilling system 100 that is coupled to drill bit 102 and provides steering to the drill bit 102, mud-pulse telemetry 80 to support MWD/LWD activities, stabilizer actuation through fluid flow control, and a rotary steerable tool used for steering the wellbore 12 drilling of the drill bit 102.

In one or more embodiments, wellbore 12 may be substantially vertical, substantially horizontal, or at any deviation. Steering of the drill bit 102 may be used to facilitate a deviation 44, or a series of deviations 44, and/or steering may be used to maintain a section in a wellbore 12 without deviations, since steering control may also be needed to prevent deviations in the wellbore 12. The rotary steerable drilling system 100 may also comprise a pad assembly 142 disposed or positioned at or about the drive shaft 170 or otherwise coupled to the drive shaft 170 above the drill bit 102, according to one or more aspects of the present disclosure.

At the surface 16, the drilling rig 22 may be configured to facilitate drilling the wellbore 12. The drilling rig 22 may include a turntable 26 that rotates the tubing string 30 and the drill bit 102 together about the longitudinal axis X1. The turntable 26 may be selectively driven by an engine 27, and selectively locked to prohibit rotation of the tubing string 30. A hoisting device 28 and swivel 34 may be used to manipulate the tubing string 30 into and out of the wellbore 12. To rotate the drill bit 102 with the tubing string 30, the turntable 26 can rotate the tubing string 30, and a drilling fluid 36 such as mud can be circulated downhole by mud pump 23. The drilling fluid 36 is illustrated as downhole drilling fluid 32 in FIG. 1 .

In one or more embodiments, the rotary steerable drilling system 100 comprises a pad assembly 142 that may be expanded or extended to contact a wall of the wellbore 12 so that the rotary steerable system 100 is steerable in a desired direction. For example, a force is applied using drilling mud pressure and fluid by creating a seal between a high pressure side, inner diameter of a bore of the pad assembly 142, where the drilling mud is entering and the outer diameter of the bore of the pad assembly 142, which has a lower pressure. The drilling mud or other mud may be a calcium chloride brine mud, for example, which can be pumped through the tubing string 30 and passed through the rotary steerable drilling system 100. In one or more embodiments, the rotary steerable drilling system 100 may include a pad pusher and a rotary valve that selectively applies pressure to at least one output flow path in order to hydraulically actuate the pad pusher. Additionally, the mud can be pumped through a mud motor (not expressly illustrated in FIG. 1 ) in the BHA 101 to turn the drill bit 102 without having to rotate the tubing string 30 via the turntable 26.

Embodiments of the BHA 101 incorporate one or more sensors in the drill bit 102 or the drill bit assembly coupling the drill bit to drive shaft 170. The one or more sensors are configured to sense one or more parameters, such as weight-on-bit, torque-on-bit, bending-at-bit, or other parameters associated with the drill bit 102 and/or with the operation of the drill bit. The one or more sensors are configured to provide output signals indicative of the levels or values of the parameters being sensed by the respective one or more sensors.

In various embodiments, a controller, such as controller 211 (FIG. 2A, 2B) is located within the BHA 101, and is configured to receive the output signals from the one or more sensors. The controller further comprises one or more processing devices (e.g., computer system 400, FIG. 4 ), which are configured to operate, using software algorithm(s), to process the output signal provided by the one or more sensors, and to generate one or more control output signals based at least in part on the received sensor output signals. The control output signals are communicated to one or more actuator controllers that are configured to control the actuation of the devices included in the bottom hole assembly of the drill string, which may include but are not limited to a rotary steerable system, such as the pad assembly as described above.

In various embodiments that include a rotary steerable system, the control output signals are configured to control the operation of the actuator devices in a manner that thereby controls the steering of the drill bit in order to direct the drill bit to advance the borehole of wellbore 12 along the desired trajectory or path. In various embodiments, the controller is able to provide closed loop control of the operation of the steering system based on the output signals from the one or more sensors without the need for input from another device, such as a computer or smart device located above surface 106. In various embodiments, the controller is configured to operate to provide the control output signal in real-time or in near real-time, thus reducing the time needed to make adjustments to the steering devices included in the rotary steerable system, and thereby providing a more accurate and consistent guidance of the drilling operation. In various embodiments, the output signals provided by the controller may be provided to other devices, as further described for example with respect to FIG. 2B, are included in the bottom hole assembly and which control some aspect of the operations being performed by the bottom hole assembly and/or by the drill bit.

Referring back to FIG. 1 , embodiments of well system 10 may include a user interface device, as illustratively represented in FIG. 1 by user interface 50. User interface 50 may include a computing device 51, such as a personal computer, a lap-top computer, or some other type of user interface device, such as a smart phone. In various embodiments, user interface 50 includes one or more input/output devices 52, for example a display device such as a computer monitor, which is configured to provide visual display of data and other information related to well system 10 and/or to a fluid treatment process being performed on or modeled for wellbore 12. In various embodiments, the display device is configured to display information regarding data received at user interface 50 from the BHA 101, for example from a controller located in the BHA, and related to the status and/or other parameters associated with the downhole drilling operation(s) being performed by the BHA.

In various embodiments, user interface 50 is communicatively coupled to the BHA 101 in order to receive output signals that are either provided directly from the one or more sensors located in the drill bit 102, and/or as data derived from the output signals provided by the one or more sensors in the drill bit. In various embodiments, user interface 50 is configured to receive the output signals and/or the data corresponding to the output signals provided by the one or more sensors, and to process the received signals and/or data in order to generate control outputs related to the drilling operation being performed by the drill bit 102 in real or near real time. The control outputs may be used to determine that the operating parameters for the current drilling operation, such as weight-on-bit and/or drill bit rotational speed, tool face, duty cycle, should be maintained or corrected, and if the operating parameters need correction, to provide output control signals to control the operation of one or more devices in order to provide the desired corrections.

For example, control output signals may include control signals directed to the devices controlling the hoist device 28 in order to adjust the weight-on-bit being applied to the drilling operation. Outputs control signals may include control signals directed to the engine 27 configured to adjust the speed of the rotary turntable 26, and thus the rotational speed of the drill bit 102. In various embodiments, the output control signals may be communicated downhole, for example to BHA 101 and/or to a steering system controlling the operation of pad assembly 142, the communicated output control signals configured to control the operation of the steering system in order to correct and/or provide control parameter to the steering system in order to direct the drilling direction of the drilling operation being performed by the drill bit 102. In each of these embodiments, the closed loop confirmation and/or control of the drilling operation based on the output signals provided by the one or more sensors positioned within the drill bit 102 may be performed in real time or near real time, and in various embodiments on a continuous basis or at a predetermined interval in time. For example, the closed loop confirmation and/or control operations may be performed without having to stop the drilling operation of the drill bit and/or without the need to only perform the measurements and make the determinations regarding the need for adjustments to the drilling operation based on some minimum amount of advancement of the borehole.

The computer system of user interface 50 may include one or more additional input devices, such as a computer keyboard, computer mouse, and/or a touch screen that allows a user, such as a technician or engineer, to provide inputs to user interface 50, which may include requests for information regarding the status of well system 10 and/or inputs that may be used to direct the operations of the downhole drilling operation, for example to provide drilling plans, wellbore models, and/or other data to a controller located in the BHA. Connections between user interface 50 and other devices included in in well system 10 may be provided by wired and/or wireless communication connection(s), or other methods of communications, such as use of mud pulse telemetry, as illustratively represented by lightning bolt 55. In various embodiments, a field technician or engineer may provide inputs to the drilling operation being performed by the drill bit 102 using user interface 50, wherein the inputs may be made based at least in part in view of information derived either directly or indirectly from the output signals provided by the one or more sensors located within the drill bit assembly.

In various embodiments, user interface 50 is communicatively coupled to a non-volatile computer readable memory device 53. Memory device 53 is not limited to any particular type of memory device. Memory device 53 may store instructions, such as one or more applications, that when operated on by the processor(s) of the computing device 51, are configured to control the operations of one or more of the devices included in well system 10. Any combination of one or more machine readable medium(s) may be utilized. The machine readable medium may be a machine readable signal medium or a machine readable storage medium. A machine readable storage medium may be, for example, but not limited to, a system, apparatus, or device, which employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code.

More specific examples (a non-exhaustive list) of the machine readable storage medium would include the following: a portable computer diskette, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine readable storage medium may be any tangible non-transitory medium that can contain, or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine readable storage medium is not a machine readable signal medium. In various embodiments, user interface 50 may include a computer system such as computer system 400 as illustrated and described below with respect to FIG. 4 .

FIG. 2A depicts a bottom hole assembly 200, according to various embodiments. As shown in FIG. 2A, bottom hole assembly (BHA) 200 includes a drill bit assembly 201 positioned at the face 202 of the BHA, a rotary steerable system (RSS) 210 is coupled to the drill bit assembly 201, and a telemetry section 220 is coupled to RSS 210. In various embodiments, BHA 200 is an embodiment of the bottom hole assembly 101 as illustrated and described above with respect to FIG. 1 , including RSS 210 comprising the rotary steerable system 100 of FIG. 1 , wherein BHA 200 may be configured to perform any of the functions, and to provide any of the features as described with respect to the bottom hole assembly of well system 10.

Referring to FIG. 2A, drill bit assembly 201 includes one or more sensor 203 built into the drill bit and/or the shaft mechanically coupling the drill bit assembly 201 to the rotary steerable assembly of RSS 210. By positioning the one or more sensor 203 within the drill bit assembly 201, the sensor(s) may provide outputs in real-time corresponding to the forces and/or other parameters associated with the drill bit assembly directly, and without the inaccuracies that may be caused by having the sensor(s) positioned in another part of the drill string, for example in a position uphole of the drill bit, and for example uphole of the steering assembly used to direct the drilling direction of the drill bit assembly 201.

The one or more sensors 203 may be configured to sense one or more parameters associated with the drill bit assembly 201 and/or the operation of the drill bit. For example, the one or more sensors 203 may be configured to measure parameters such as torque-on-bit, bending-on-bit, weight-on-bit, a rotational speed of the bit, vibration level(s) present during the operation of the bit, temperature of the bit and/or the drilling fluid present within the bit, angle of inclination and azimuth of the face 202 of the drill bit, and/or potential formation properties that may be determined based on the in-bit measurements. The one or more sensors 203 are configured to generate output signal(s), such as electrical output signals, which may be communicated in various embodiments through a connector 204, which is electrically, optically, or otherwise communicatively coupled to a wired link 215, such as a multi-conductor cable, which is coupled to a controller 211. In various embodiments, controller 211 is located in the rotary steerable system 210 portion of the BHA 200.

In various embodiments, controller 211 includes various components, such as an interface configured to receive the outputs signals provided by the one or more sensors 203, and a processing system including one or more computer processors and associated computer memory, which are configured to process the signals received at the interface from the one or more sensors. In various embodiments, controller 211 is configured, in various embodiments using software programming and/or software algorithms, to generate steering control signals based at least in part on the output signals received at the controller 211 from the one or more sensors 203.

The steering control signals generated by controller 211 may then be output to one or more actuators, such as first pad actuator 213 and second pad actuator 217. As shown in FIG. 2A, first pad actuator 213 is mechanically coupled to a first pad 212, and second pad actuator 217 is mechanically coupled to a second pad 216. First pad 212 includes an outer surface 214 that is configured to make contact with a formation material proximate to the first pad 212 when BHA 200 is positioned within a borehole, such as the borehole of wellbore 12 (FIG. 1 ), and when actuated to an extended position, to apply a force against the formation material that may be transferred to and direct the drilling direction of drill bit assembly 201 when the drill bit assembly is being operated to advance the borehole. Similarly, second pad 216 includes an outer surface 218 that is configured to make contact with the formation material proximate to the second pad 216 when BHA 200 is positioned within a borehole, such as the borehole of wellbore 12 (FIG. 1 ), and when actuated to an extended position, to apply a force against the formation material that may be transferred to and direct the drilling direction of drill bit assembly 201 when the drill bit assembly is being operated to advance the borehole.

As shown in FIG. 2A, the first pad 212 is actuated to an extended position, while the second pad 216 is actuated to a retracted position. As such, the outer surface 214 of the first pad 212 may be brought into contact with the formation material proximate to outer surface 214, and due to the actuation of the first actuator pad to the extended position, may exert a force on the rotary steerable system 210, and thus the drill bit assembly 201, in a “downward” direction relative to the centerline 205 of the BHA 200, as illustratively represented by arrow 206. In combination with the second pad actuator 217 controlling the second pad 216 to assume a retracted position, the overall result is that drill bit assembly 201 may be steered to a drilling direction more along the line indicated by dashed line 207 as compared to the centerline 205 of the BHA 200. As such, controller 211 is configured to provide steering control signals to first pad actuator 213 to actuate the first pad 212 to an extended position, and to provide steering control signals to second pad actuator 217 to actuate second pad 216 to a retracted position, and thereby urge the direction of the borehole being formed by the drill bit assembly 201 in a “downward” direction.

Controller 211 is also configured to provide steering control signals that, when received by the first pad actuator 213 and by the second pad actuator 217, may be configured to alter the extended and/or retracted positions of the first pad 212 and the second pad 216, and thereby again alter the steering path for the drill bit assembly 201 forming the borehole. For example, controller 211 may, based at least in part on the signals provided by the one or more sensors 203, provide steering control signals to the first pad actuator 213 to actuate the first pad 212 to a retracted position, and to the second pad actuator 217 to actuate the second pad 216 to an extended position, thereby exerting a force on the formation material proximate to the first pad and the second pad that urge the BHA 200, and thus drill bit assembly 201, in an “upward” direction, as illustratively represented by arrow 208, within the borehole where the drill bit assembly is located. The urging of the drill bit assembly 201 in the “upward” direction may cause the direction of the borehole being formed by the operation of the drill bit assembly 201 to move in a direction along dashed line 209 that is in a direction away from the centerline 205 and different from the direction indicated by dashed line 207. Thus, by controlling the steering control signals provided to the first pad actuator 213 and the second pad actuator 217, controller 211 is configured to control the steering of the direction of the drilling being performed by the BHA 200 and the drill bit assembly 201.

It would be understood that the use of a first and a second set of actuators and pads as shown in FIG. 2A is a non-limiting example, and other arrangements are possible and are contempt for use with controller 211 and BHA 200. For example, for tools that have a fully rotating SSR system, the rotary steerable system 210 may be configured so that as the tool is rotated, the first pad 212 and the second pad 216 will be alternately extended and retracted in corresponding opposite configurations so that as the tool rotates, the first and second pad will assume a desired positioning to direct the drill bit assembly 201 in a desired direction. In addition, embodiments of BHA 200 are not limited to having any particular number of actuators, and in various embodiments may include a single actuator, for example a ring encircling a portion of the rotary steerable system 210 that may be extended in any direction radially from the outer perimeter of the rotary steerable system. In various embodiments, a plurality of actuatable pads that may include two, three, or more than three pads may be included in the rotary steerable system, and which may be controlled in a coordinated manner by steering control signals provided by controller 211 in order to provide steering for the BHA 200 and the drill bit assembly 201. In various embodiments, all of the actuator devices, such as pads, may be positioned at a same radial position along a longitudinal axis of the BHA 200. In alternative embodiments, one or more of the actuator devices, such as pads, may be arranged in a staggered or in-line arrangement, but positioned at one or more different locations relative to the longitudinal axis of the BHA 200.

In addition, the type of actuators used to control any of the steering mechanisms used to steer the BHA 200 and the drill bit assembly 201 are not limited to any particular type of actuator, or to any particular mechanism(s) for actuation of pads or other steering devices. In various embodiments, actuator mechanism(s) included in the BHA 200 may control a flow of a portion of the drilling fluid provided to BHA 200 from the surface of a wellbore environment to provide the actuation of the pads or other actuation mechanism. In various embodiments, the actuator mechanism(s) may be electronically controlled using devices such as servo or stepper motors, to control the positioning, and thus the steering of the BHA 200, and thus the drill bit assembly 201, based on steering control signals provided by controller 211.

In various embodiments, control of the actuators such as first pad actuator 213 and second pad actuator 217, is provided completely based on steering control signals generated and provided to the actuators by controller 211. The use of controller 211 provides advantages including that the processing of the output signals from the sensors located within drill bit assembly 201 are coupled directly to the controller, allowing the controller to receive and to process these sensor output signals in real-time or near real-time, without the need to transmit the information associated with the sensor output signals from the one or more sensors to a device located at the surface, and then to process these signal at the remote device and to transmit control signals back down to the rotary steerable system 210. As such, a more rapid response to the parameters and conditions present and being measured at the drill bit assembly 201 by the one or more sensors 203 may be provided. In addition, because the one or more sensor 203 are located within the drill bit assembly 201, and downhole of the rotary steerable system 210, a more accurate indication of the parameters and the actual conditions at the drill bit assembly are provided by the one or more sensors to the controller 211. The more accurate sensing provided by the one or more sensors, along with the more rapid processing and generation of the steering control signals provided by controller 211, may provide a quicker reaction time and a more accurate control process of the steering of the drill bit, resulting in a more accurate drill path along the desired borehole direction.

Embodiments of BHA 200 include a telemetry section 220. Telemetry section 220 may include a transceiver 221 configured to transmit and to receive data and/or other information to one or more devices located remotely from BHA 200, as illustratively represented by lightning bolt 223. In various embodiments, transceiver 221 is coupled though link 219 to controller 211, and is configured to provide communications between controller 211 and the one or more devices located remotely from BHA 200, such as but not limited to a computer device or user interface device, such as user interface 50 (FIG. 1 ) located at or above a surface where the wellbore operations are being performed.

Transceiver 221 may be linked to the one or more remote devices using any type of communication apparatus and techniques applicable to wellbore communications, including wired connections, wireless connections, using electrical and/or optical communication media, and/or other media such as mud pulse communications. The types of information and/or data transmitted from and received by transceiver 221 is not limited to any particular type of information or data, and is not limited to utilizing a particular communication protocol or format. Information or data transmitted from transceiver 221 may include data related to the values being sensed by the one or more sensors located at or within the drill bit assembly 201. Information or data received at transceiver 221 may include information or data related to any aspect of the drilling operation being performed by the BHA 200, including drill path information or drilling model information, which may be used by controller 211 to adjust and/or to maintain the desired trajectory of the borehole being drilled by the drill bit assembly 201.

In various embodiments, transceiver 221 is configured to receive the output signals provided by the one or more sensors 203, either directly over link(s), such as link 215 and 219, or through links coupled through controller 211. The transceiver 221 may be configured to communicate the output signals directly, or using signals processed from the output signals, to one or more remote devices, such as but not limited to a computer device such as computer system 50 (FIG. 1 ). Using computer system 50 as an example, the computer system may be configured to receive the signals communicated from transceiver 221, which include the output signals provided by the one or more sensors 203 and/or data derived from these output signals. Computer system 50 may be configured to process these received communications, and to perform one or more functions based on the processing of the received communication provided by transceiver 221.

In various embodiments, computer system 50 is configured to determine, based at least in part on the received communications, that the drilling operations is proceeding according to the desired drilling plan. In various embodiments, computer system 50 is configured to determine, based at least in part on the received communications from transceiver 221, that an adjustment to one or more parameters associated with the drilling operation requires adjustment. In various embodiments, based on a determination that an adjustment or adjustments to the drilling operation is/are required, computer system 50 may generate one or more outputs, which are communicated to other devices at the surface, which cause the other device(s) to change one or more parameters associated with the drilling operation. For example, computer system 50 may provide output control signal(s) to various devices controlling the weight of the drill string that is being applied the drill bit assembly 201 in order to change the weight-on-bit at the drill bit. In various embodiments, computer system 50 may provide output control signal(s) to device(s) that are controlling the rotational speed of the drill string, and thus the rotational speed of the drill bit, and thereby change rotational speed of the drilling operation. In various embodiments, computer system 50 determines that changes need to be made for example with respect to the steering of the drill bit assembly. In such instances, computer system 50 may communication output signals downhole to the transceiver 221, which in turn may process and/or pass the output signals to the controller 211. These output signals provided by the commuter system 50 may in turn be processed by controller 211 to make one or more adjustments to the steering mechanism being utilized by RSS 210 to further direct the steering of the drilling operation.

By having the flexibility to utilize the output signals provided by the one or more sensors 203 either directly by the controller 211, directly based on control output signal generated by a remote device based on these output signals from the one or more sensors, or a combination thereof, the systems, apparatus, methods and techniques as described herein can provide real-time or near real-time control over the drilling operations being performed by the drill bit assembly 201 that is based, at least in part, on the measurements provided by the one or more sensors located in drill bit assembly itself. Such features in various embodiments provide faster closed-loop control which in turn may provide more accurate drilling of a borehole along a pre-planned and desired drill path.

FIG. 2B depicts a functional block diagram of one or more bottom hole assemblies 250, according to various embodiments. In the functional block diagram of the bottom hole assemblies (BHA) 250, same or similar components as included and described above with respect to FIG. 2A and BHA 200 are designated using the same reference numbers, respectively. For example, in FIG. 2B the BHA 250 includes a drill bit assembly 201 having a drill bit face 202, and one or more sensors 203 located within the drill bit assembly. The one or more sensors 203 are electrically and communicatively connected through electrical connector 204 and through wired connection 215 to controller 211 positioned in BHA section 251 of BHA 250.

In a manner similar to or the same as described above for BHA 200 (FIG. 2A), BHA 250 may include having the controller 211 communicatively coupled through wired connection 219 to transceiver unit 221, wherein transceiver 221 is included as part of a telemetry section 220 of BHA 250, and is configured to provide communications with other devices, such as devices located at the surface of a borehole where BHA 250 is being deployed, as illustratively represented by lightning bolt 223. In various embodiments, the devices of BHA 250 may be configured to provide any of the features and/or to perform any of the function ascribed to the corresponding devices having the same reference numbers as described with respect to BHA 200 and FIG. 2A.

As illustrated in FIG. 2B, BHA section 251 of BHA 250 includes a actuatable device 252 configured to be actuated or otherwise controlled by an actuator 254. Actuator 254 is communicatively linked, for example using a wired connection 253, to the controller 211. Actuator 254 may be configured to receive output signals from controller 211, and to control the auction and/or operation of actuatable device 252 based, at least in part, on the output control signals provided to the actuator 254 over connection 253 from controller 211. As described above, the output control signals provided by the controller 211 may in turn be based at least in part, on the sensor output signals provided to the controller 211 by the one or more sensors 203 positioned within drill bit assembly 201.

Examples of the type of devices that may be configured as the actuatable device 252 are not limited to any particular device(s), or to any particular types of devices, and may include any type of device(s) that may be included as part of a bottom hole assembly, such as BHA 250. For example, actuatable device 252 may comprise a bent motor configured to be controlled by actuator 254 to provide a bend or angle in the BHA section 251 to provide directional steering of the drill bit relative to the centerline 205 of the BHA. In various embodiments, actuator 254 is configured to control a direction and/or an amount of bend provided by the bent motor based, at least in part, on control signals received by actuator 254 from controller 211, which in turn are based, at least in part, on the output signals provided by the one or more sensors 203 positioned within the drill bit assembly 201.

In various embodiments, actuatable device 252 comprises an eccentric ring having a portion of the eccentric ring that can be extended away from the centerline 205 on one side of the centerline that greater than the outer surface of the BHA section 251, and thereby provide directional steering of the drill bit assembly 201 within a borehole relative to the centerline. In various embodiments, actuator 254 is configured to control the direction and/or the amount of extension of the eccentric ring based, at least in part on control signals received by the actuator 254 from controller 211, which in turn are based, at least in part, on the output signals provided by the one or more sensors 203 positioned within the drill bit assembly 201.

In various embodiments, actuatable device 252 comprises an thruster, such as a weight-on-bit (WOB) thruster, or a torque compliant device. In various embodiments, a thruster or a torque compliant device may be a hydraulic, pneumatic, or mechanical device that is configured to control, cushion, and/or dampen forces associated generating the forces applied at the drill bit face 202 to formation material being processed and removed by the drill bit assembly. In embodiments where the thruster or torque compliant device is hydraulically or pneumatically controlled, actuator 254 may be configured to control various aspect, such as flow rates and pressures, of the fluid being applied to through the thruster or torque compliant device to the drill bit assembly based, at least in part, on the output signals provided by the one or more sensors 203 positioned within the drill bit assembly 201. In embodiments where the thruster or torque compliant device is a mechanically controlled device, for example utilizing a spring stack, actuator 254 may be configured to control the positing of a sleeve or other device that controls a preload on the spring stack, and thereby controls the operation of the thruster, based, at least in part on control signals received by the actuator 254 from controller 211, which in turn are based at least in part of the outputs signals provided by the one or more sensors 203 located within the drill bit assembly.

In various embodiments, actuatable device 252 comprises a friction reduction tool. In various embodiments, a friction reduction tool is a device, such as a mechanical vibration tool, which provides mechanical motion, such as a vibratory motion in the BHA that aids in the BHA, such as BHA 250, being advanced within the borehole past various obstructions and/or constrictions, such as bends in the path of the borehole, where the BHA is being deployed. In various embodiments, actuator 254 is configured to control one or more aspects of the operation of the friction reduction device, such as an operational frequency and/or range of motion of the friction reduction tool, based, at least in part on control signals received by the actuator 254 from controller 211, which in turn are based at least in part of the output signals provided by the one or more sensors 203 positioned within the drill bit assembly 201.

In various embodiments, actuatable device 252 comprises an adjustable stabilizer. An adjustable stabilizer in various embodiments is a device that is designed to act mechanically to allow for control of the positioning of the BHA within a portion of the borehole where the BHA is deployed. In various embodiments, the adjustable stabilizer may act against the walls of the borehole to centralize the BHA within the borehole. In various embodiments, the adjustable stabilizer may position the BHA relative to the walls of the borehole in order to steer the BHA through the borehole and/or to steer the direction of a drilling operation being performed by BHA. The adjustable stabilizer may function as a stabilizer, for example by damping vibrations of the BHA that may be generated for example by the operation of the BHA. In various embodiments, a controllable mechanism, such as a sliding sleeve or sleeves, are incorporated as part of the adjustable stabilizer and are configured to allow for adjustment of an overall diameter and/or relative axial positioning of the adjustable stabilizer to enact effects on the steerability/stability of the BHA. In various embodiments, actuator 254 is configured to control one or more aspects of the operation of the adjustable stabilizer, for example through control over the adjustable sleeve(s) of the adjustable stabilizer, based, at least in part on control signals received by the actuator 254 from controller 211, which in turn are based at least in part on the output signals provided by the one or more sensors 203 positioned within the drill bit assembly 201.

For each of the embodiments of devices being controlled by a controller, such as controller 211, providing output control signals, the output control signals may be based on the signals received from the one or more sensors positioned within the drill bit assembly alone, or may be based on the signals received from the one or more sensors positioned within the drill bit assembly in combination with signals, data, instructions, or other type of information generated by the controller itself and/or as received at the controller from other devices. Such other devices may include other tools and/or sensor(s) positioned within the BHA where the controller is located, and/or devices outside of the BHA where the controller is located, such as devices located at the surface or within other portion of a tool string coupled to the BHA.

FIG. 3 illustrates a flowchart of a method 300, according to various embodiments. In various embodiments, method 300 may be performed by some combination of the components illustrated and described above with respect to well system 10. In various embodiments, method 300 may be performed by a bottom hole assembly, such as but not limited to BHA 200 as illustrated and described above with respect to FIG. 2A or to BHA 250 as illustrated and described above with respect to FIG. 2B.

As shown in FIG. 3 , method 300 includes commencing a downhole drilling operation (block 302). In various embodiments, commencing a downhole drilling operation includes positioning a bottom hole assembly, such as BHA 200 (FIG. 2A), or BHA 250 (FIG. 2B), at a starting point for drilling a borehole, or positioning the bottom hole assembly within an existing borehole that is to be advanced through a formation material. The bottom hole assembly includes one or more sensors located within the drill bit assembly and in a position within the bottom hole assembly that is downhole from one or more actuatable devices), such as steering actuator(s) included in the bottom hole assembly, the steering actuator(s) configured to provide steering for the direction of drilling to be performed by the bottom hole assembly.

Embodiments of method 300 include sensing one or more parameters associated with the drilling operation using one or more sensors located at or within the drill bit assembly (block 304). The one or more sensors may be configured to sense parameter(s) associated with the drill bit assembly and/or the drilling operations. Sensed parameters may include measurements of torque-on-bit, bending-on-bit, weight-on-bit, rotational speed of the drill bit, vibration, shock, temperature, and pressure. Sensing one or more parameter(s) includes providing outputs signals, such as but not limited to electrical and/or optical output signals, which are indicative of the values of the sensed parameter(s), and providing these output signals to a controller, such as but not limited to controller 211 (FIGS. 2A, 2B).

Embodiments of method 300 include receiving the output signals from the one or more sensors at a controller, wherein the controller is located in the bottom hole assembly (block 306). Receiving the output signals in some embodiments includes receiving an electrical signal, such as a voltage level, which is indicative of a measured value sensed by the one or more sensors.

Embodiments of method 300 include processing the output signals received from the one or more sensors, and determining control signals based, at least in part, on the one or more sensor output signals (block 308). In various embodiments, the control signal include steering control signals configured for controlling the operation of a steering control system, such as the rotary steerable systems as described herein, and any equivalents thereof. In various embodiments, the control signal include signals configured for controlling the operation of any of the bottom hole tools that may be included in the BHA system, such as but not limited to a bent motor, a thruster or torque compliant tool, friction reduction tool, or other actuatable tools that may be included in a bottom hole assembly. In various embodiments, processing of the output signal includes conditioning of the received output signals, such as analog-to-digital conversion of the output signals, filtering of the signals, and performing noise cancellation on the received output signals. In various embodiments, processing of the output signals to determine the control signals includes using software programming and/or various algorithms stored in the controller to determine the desired steering control signals based at least in part of the received output signal provided from the one or more sensors.

Embodiments of method 300 include providing the control signals to one or more device actuators included in the bottom hole assembly (block 310). In various embodiments, providing control signals includes providing steering control signals are configured to provide control signals to the one or more steering device actuator so that one or more steering device actuators may then control associated actuator devices, such as actuator pads, in a manner configured to provide a desired steering direction for the drill bit assembly to advance further into the formation material at the face of the drill bit. In various embodiments, providing control signals includes providing control signals to an actuator that controls a downhole tool included in the bottom hole assembly, the control signals configured to provide data and/or instructions for the actuator to use in order for the actuator to control the operation an associated bottom hole tool in a desired matter.

Embodiments of method 300 include determining whether the drilling operation has been completed (decision block 312). When a determination is made that the drilling operation has not been completed (“NO”) branch extending from decision block 312), method 300 may proceed block 304, including continuing to sense one or more parameters associated with the drilling operation using the one or more sensors located at the drill bit. This looping process of sensing parameters, providing the output signal from the sensors associated with the sensed parameters to the controller, determining control signals based at least in part on the senor output signals, and providing the control signals to one or more device actuators in order to control the operation(s) of one or more tools included in the bottom hole assembly of the drill bit assembly may be repeated iteratively any number of times until the determinant is made that the drilling operation is completed. In various embodiments, the feedback loop as described above occurs on a real-time or on a near real-time basis, and may be performed without the need to transmit or to receive data and/or instruction to/from an outside device, such as remote computer device located for example above the surface where the borehole is being drilled.

When a determination is made that the drilling operation has been completed (“YES”) branch extending from decision block 312), method 300 may proceed to stopping the drilling operation (block 314).

In various embodiments, method 300 includes transmitting signals to a remote device (block 320). In various embodiments, the remote device may be a computer device or user interface device, such as user interface 50 (FIG. 1 ), which is located remotely from the bottom hole assembly, for example at a surface above the borehole where the bottom hole assembly is positioned. In various embodiments, the transmitted signals include data related to the values being provided in the output signals from the one or more sensors located at or within the drill bit assembly. In various embodiments, the transmitted signals may include data generated by the controller include in the bottom hole assembly, for example data based at least in part on the output signals provided by the one or more sensors.

In various embodiments, method 300 includes receiving inputs from a remote device at the controller located in the bottom hole assembly (block 322). In various embodiments, the remote device is a computer device or user interface, such as user interface 50 (FIG. 1 ), which is located at the surface. In various embodiments, the inputs received from the remote device may include an instruction that the drilling operation has been completed (dashed line 324), in which case the method 300 proceeds to the “YES” branch of decision block 312, which in turn would direct the method to stop the drilling operation (block 314). In various embodiments, the inputs received from the remote device may include drill path information, such as drill model or drill directional information, which the controller located at the bottom hole assembly may utilize to further determine what will be included in the control signals used to control the actuatable devices of the bottom hole assembly, such as but not limited to a rotary steerable system of the bottom hole assembly going forward. In various embodiments, a remote device may be configured to provide control signals to other devices, such as other devices located at the surface, the other devices configured to adjust one or more parameters associated with the drilling operation being performed downhole by the drill bit assembly. Non-limiting examples of other devices may include devices configured to control the weight-on-bit and/or the torque-on-bit of the drilling assembly, and/or devices configured to control the rotational speed of the drilling assembly from the surface.

FIG. 4 illustrates a block diagram of an example computing system 400 that may be employed to practice the concepts, methods, and techniques as disclosed herein, and variations thereof. Computing system 400 includes a plurality of components of the system that are in electrical communication with each other, in some examples using a bus 403. Embodiments of computing system 400 may include any suitable computer, controller, or data processing apparatus capable of being programmed to carry out the methods and for controlling apparatus as further described herein. In various embodiments, one or more components illustrated and described with respect to computing system 400 may be included in computer system 50 as illustrated and described with respect to FIG. 1 . In various embodiments, one or more components illustrated and described with respect to computing system 400 may be included in controller 211 as illustrated and described with respect to FIGS. 2A and 2B, wherein controller 211 may be configured to perform any of the functions and to provide any of the features ascribable to computing system 400.

Referring back to FIG. 4 , computing system 400 may be a general-purpose computer, and includes a processor 401 (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer system 400 includes memory 402. The memory 402 may be system memory (e.g., one or more of cache, SRAM, DRAM, zero capacitor RAM, Twin Transistor RAM, eDRAM, EDO RAM, DDR RAM, EEPROM, NRAM, RRAM, SONOS, PRAM, etc.) or any one or more of the possible realizations of machine-readable media configured to store data and/or program instructions in an electronic format. The computer system also includes the bus 403 (e.g., PCI, ISA, PCI-Express, HyperTransport® bus, InfiniBand® bus, NuBus, etc.) and a network interface 405 (e.g., a Fiber Channel interface, an Ethernet interface, an internet small computer system interface, SONET interface, wireless interface, etc.). Bus 403 may be configured to provide communications between any of the devices included in computing system 400. Network interface 405 may be configured to provide communications between computing system 400 and other computing devices.

Embodiments of computer system 400 include a controller 410. The controller 410 may be configured to control the different operations that can occur in the response inputs from sensors 412 and/or calculations based on inputs from sensors 412 (such as sensors 203 located in or at a drill bit assembly, FIGS. 2A, 2B), using any of the techniques described herein, and any equivalents thereof, to provide steering control outputs to actuators 414. For example, the controller 410 may communicate steering control signals to the appropriate equipment, devices, such as actuator control devices etc. to thereby control actuator(s) used to steer a drill bit assembly being used in a wellbore drilling operation to advance a borehole through a formation material.

Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor 401. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 401, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in FIG. 4 (e.g., audio cards, additional network interfaces, peripheral devices, etc.). As illustrated in FIG. 4 , the processor 401 and the network interface 405 are coupled to the bus 403. Although illustrated as also being coupled to the bus 403, the memory 402 may be coupled to the processor 401 only, or both processor 401 and bus 403.

As shown in FIG. 4 , controller 410 is coupled to one or more sensors 412, and to one or more actuators 414 using any type of wired or wireless connection(s). The one or more sensors includes sensor(s) located at or within a drill bit assembly, such as sensors 203 positioned within a drill bit assembly 201 (FIGS. 2A, 2B). Controller 410 is configured to receive sensor output signals, such as electrical and/or optical signals, as provided as an output from the sensor(s) 412. In various embodiments, controller 410 may be configured to perform signal processing, such as analog-to-digital signal processing on the received sensor output signals, and to provide the processed sensor output signals to processor 401 and/or to memory 402 via bus 403. Sensor(s) 412 may include any of the sensors associated with sensing one or more parameters associated with or in the areas proximate to the drill bit assembly included as part of a bottom hole assembly that includes computing system 400. Controller 410 may include circuitry, such as analog-to-digital (A/D) converters and buffers that allow controller 410 to receive electrical signals directly from one or more of sensors 412.

Processor 401 may be configured to execute instruction that provide control over one or more actuators 414 of a rotary steerable system as described in this disclosure, and any equivalents thereof. For example, processor 401 may control operations of one or more actuators 414 that in turn control the actuation of devices, such as first pad 212 and second pad 216 of the rotary steerable system 210 as illustrated and described above with respect to FIG. 2A. The controller 410 as shown in FIG. 4 may provide control output signals to the actuators 414 in order to control actuator devices coupled to and control by actuators 414 in order to steer a drill bit assembly that is coupled to the rotary steerable system that includes actuator(s) 414. In various embodiments, processor 401 may be configured to execute instructions and to provide control signals for one or more actuators 414, wherein the one or more actuators 414 are configured to control the operation of one or more downhole tools including in the bottom hole assembly, such as but not limited to bent motor, thruster or torque complaint tools, and/or friction reduction tools.

With respect to computing system 400, basic features here may easily be substituted for improved hardware or firmware arrangements as they are developed. In some examples, memory 402 includes non-volatile memory and can be a hard disk or other types of computer readable media which can store data and program instructions that are accessible by a computer, such as magnetic cassettes, flash memory cards, solid state memory devices, digital versatile disks (DVDs), cartridges, RAM, ROM, a cable containing a bit stream, and hybrids thereof.

It will be understood that one or more blocks of the flowchart illustrations and/or block diagrams, and combinations of blocks in the flowchart illustrations and/or block diagrams, can be implemented by program code. The program code may be provided to a processor of a general-purpose computer, special purpose computer, or other programmable machine or apparatus. As will be appreciated, aspects of the disclosure may be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects may take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc.

Computer program code for carrying out operations for aspects of the disclosure may be written in any combination of one or more programming languages, including an object oriented programming language such as the Java® programming language, C++ or the like; a dynamic programming language such as Python; a scripting language such as Perl programming language or PowerShell script language; and conventional procedural programming languages, such as the “C” programming language or similar programming languages. The program code may execute entirely on a stand-alone machine, may execute in a distributed manner across multiple machines, and may execute on one machine while providing results and or accepting input on another machine. While depicted as a computing system 400 or as a general purpose computer, some embodiments can be any type of device or apparatus to perform operations described herein.

As will be appreciated, aspects of the disclosure may be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects may take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc.

Any combination of one or more machine readable medium(s) may be utilized. The machine readable medium may be a machine readable signal medium or a machine readable storage medium. A machine readable storage medium may be, for example, but not limited to, a system, apparatus, or device, which employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of the machine readable storage medium would include the following: a portable computer diskette, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine readable storage medium may be any tangible medium that can contain, or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine readable storage medium is not a machine readable signal medium.

While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. In general, techniques for controlling drilling operations based at least in part on output signals provided by one or more sensors located at or within a drill bit assembly as described herein may be implemented with facilities consistent with any hardware system or hardware systems. Many variations, modifications, additions, and improvements are possible.

Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.

Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed.

Example embodiments include the following.

Embodiment 1. A system comprising: a bottom hole assembly of a drilling apparatus configured for drilling a borehole through a formation, the bottom hole assembly comprising a drill bit assembly; wherein the drill bit assembly comprises a drill bit configured to advance the borehole through the formation and one or more sensors located within the drill bit assembly, the one or more sensors configured to sense a physical parameter associated with the drill bit assembly during a drilling operation being performed by the drill bit assembly, and to provide one or more sensor output signals based on a measured parameter that is sensed by the one or more sensors, and a controller communicatively coupled to the one or more sensors, the controller configured to receive the one or more sensor output signals and to process the one or more sensor output signals in order to generate in real time one or more output control signals corresponding to control one or more devices of the bottom hole assembly.

Embodiment 2. The system of embodiment 1, wherein the one or more devices of the bottom hole assembly includes a rotary steerable system comprises one or more steering device actuators, the rotary steerable system configured to receive the one or more output control signals, and to provide one or more steering control signals to one or more steering device actuators to control steering of the drill bit assembly.

Embodiment 3. The system of embodiments 1 or 2, wherein the one or more outputs signals comprise a signal indicative of a sensed bending-on-bit force occurring at the drill bit assembly.

Embodiment 4. The system of any one of embodiments 1-3, wherein the one or more sensor output signals comprise a signal indicative of a sensed torque-on-bit force occurring at the drill bit assembly.

Embodiment 5. The system of any one of embodiments 1-4, wherein the one or more sensor signals comprise a signal indicative of a sensed weight-on-bit occurring at the drill bit assembly.

Embodiment 6. The system of any one of embodiments 1-5, wherein the controller is part of the bottom hole assembly.

Embodiment 7. The system of embodiment 6, wherein the controller is coupled to receive the one or more sensor output signals from the one or more sensors located within the drill bit assembly over a wired communication link.

Embodiment 8. The system of any one of embodiments 1 and 3-7, wherein the controller is located within a rotary steerable system of the bottom hole assembly, the rotary steerable system comprising the controller coupled to one or more steering device actuators, the controller configured to receive the one or more sensor output signals, and to provide one or more steering control signals to the one or more steering device actuators to control steering of the drill bit assembly, the one or more steering control signals based at least in part on the one or more sensor output signals.

Embodiment 9. The system of any one of embodiments 1-8, wherein the one or more bottom hole devices comprises one or more of a bent motor, a thruster, a torque compliant tool, an adjustable stabilizer, and a friction reduction tool.

Embodiment 10. A method comprising: receiving, at a controller, one or more output signals from one or more sensors located within a drill bit assembly of a bottom hole assembly positioned within a borehole; determining, by the controller and in real time, one or more output control signals based at least in part on the one or more output signals from the one or more sensors, the one or more output control signals configured to control one or more devices of the bottom hole assembly that are configured to adjust one or more parameters of a drilling operation being performed by the drill bit assembly; and outputting, from the controller and in real time, the one or more output control signals to the one or more devices of the bottom hole assembly to adjust the one or more parameters of the drilling operation being performed by the drill bit assembly.

Embodiment 11. The method of embodiment 10, wherein the controller is part of the bottom hole assembly.

Embodiment 12. The method of embodiments 10 or 11, wherein the one or more output control signals include one or more steering control signals configured to control steering of the drill bit assembly, the method further comprising provide the one or more steering control signals to one or more steering device actuators to control steering of the drill bit assembly.

Embodiment 13. The method of any one of embodiments 10-12, wherein the one or more output signals comprise a signal indicative of a sensed torque-on-bit force occurring at the drill bit assembly.

Embodiment 14. The method of any one of embodiments 10-13, wherein the one or more outputs signals comprise a signal indicative of a sensed bending-on-bit force occurring at the drill bit assembly.

Embodiment 15. The method of any one of embodiments 10-14, wherein the one or more output signals comprise a signal indicative of a sensed weight-on-bit force occurring at the drill bit assembly.

Embodiment 16. The method of any one of embodiments 10-15, wherein the one or more bottom hole devices comprises one or more of a bent motor, a thruster, a torque compliant tool, an adjustable stabilizer, and a friction reduction tool.

Embodiment 17. The method of any one of embodiments 10-16, wherein the controller is coupled to receive the output signals from the one or more sensors located within the drill bit assembly over a wired communication link.

Embodiment 18. A non-transitory computer readable medium storing computer readable instructions that when executed by a processor causes the processor to perform operations comprising: receiving, at the processor, one or more output signals from one or more sensors located within a drill bit assembly of a bottom hole assembly positioned within a borehole; determining, by the processor and in real time, one or more output control signals based at least in part on the one or more output signals from the one or more sensors, the one or more output control signals configured to control one or more devices of the bottom hole assembly that are configured to adjust one or more parameters of a drilling operation being performed by the drill bit assembly; and outputting, from the processor and in real time, the one or more output control signals to one or more one or more devices of the bottom hole assembly to adjust the one or more parameters of the drilling operation being performed by the drill bit assembly.

Embodiment 19. The non-transitory computer readable medium of embodiment 18, wherein the processor is part of the bottom hole assembly.

Embodiment 20. The non-transitory computer readable medium of embodiments 18 or 19, wherein the one or more output signals comprise a first signal indicative of a sensed torque-on-bit force occurring at the drill bit assembly or a second signal indicative of a sensed bending-on-bit force occurring at the drill bit assembly or a third signal indicative of a sensed weight-on-bit force occurring at the drill bit assembly. 

1. A system comprising: a bottom hole assembly of a drilling apparatus configured for drilling a borehole through a formation, the bottom hole assembly comprising a drill bit assembly; wherein the drill bit assembly comprises a drill bit configured to advance the borehole through the formation and one or more sensors located within the drill bit assembly and built into a drill bit shaft of the drill bit, the one or more sensors configured to sense one or more parameters indicative of a bending-on-bit direction and force level occurring at the drill bit during a drilling operation being performed by the drill bit assembly, and to provide one or more sensor output signals based on the sensed one or more parameters, and a controller communicatively coupled to the one or more sensors, the controller configured to receive the one or more sensor output signals and to process the one or more sensor output signals in order to generate in real time one or more output control signals configured to control the operation of a steering system in order to correct and/or provide control parameter to the steering system in order to direct a drilling direction of the drilling operation being performed by the drill bit.
 2. The system of claim 1, wherein the steering system comprises a rotary steerable system comprising one or more steering device actuators, the rotary steerable system configured to receive the one or more output control signals, and to provide one or more steering control signals to the one or more steering device actuators to control steering of the drill bit assembly.
 3. (canceled)
 4. The system of claim 1, wherein the one or more sensor output signals comprise a signal indicative of a sensed torque-on-bit force occurring at the drill bit assembly.
 5. The system of claim 1, wherein the one or more sensor output signals comprise a signal indicative of a sensed weight-on-bit occurring at the drill bit assembly.
 6. The system of claim 1, wherein the controller is part of the bottom hole assembly.
 7. The system of claim 6, wherein the controller is coupled to receive the one or more sensor output signals from the one or more sensors located within the drill bit assembly over a wired communication link.
 8. The system of claim 1, wherein the controller is located within a rotary steerable system of the bottom hole assembly, the rotary steerable system comprising the controller coupled to one or more steering device actuators, the controller configured to receive the one or more sensor output signals, and to provide one or more steering control signals to the one or more steering device actuators to control steering of the drill bit assembly, the one or more steering control signals based at least in part on the one or more sensor output signals.
 9. The system of claim 1, wherein the drill bit assembly further comprises one or more of a bent motor, a thruster, a torque compliant tool, an adjustable stabilizer, and a friction reduction tool.
 10. A method comprising: receiving, at a controller, one or more sensor output signals from one or more sensors located within a drill bit assembly of a bottom hole assembly positioned within a borehole, wherein the drill bit assembly comprises a drill bit configured to advance a borehole through a formation, and one or more sensors located within the drill bit assembly and built into a drill bit shaft of the drill bit, the one or more sensors configured to sense one or more parameters indicative of a bending-on-bit direction and force level occurring at the drill bit during a drilling operation being performed by the drill bit assembly, and to provide one or more sensor output signals based on the sensed one or more parameters; generating, by the controller and in real time, one or more output control signals based at least in part on the one or more sensor output signals from the one or more sensors, the one or more output control signals configured to control the operation of a steering system in order to correct and/or provide control parameter to the steering system in order to direct a drilling direction of the drilling operation being performed by the drill bit; and outputting, from the controller and in real time, the one or more output control signals to the steering system to control the operation of the steering system.
 11. The method of claim 10, wherein the controller is part of the bottom hole assembly.
 12. The method of claim 10, wherein the one or more output control signals include one or more steering control signals configured to control steering of the drill bit assembly, the method further comprising provide the one or more steering control signals to one or more steering device actuators to control steering of the drill bit assembly.
 13. The method of claim 10, wherein the one or more sensor output signals comprise a signal indicative of a sensed torque-on-bit force occurring at the drill bit assembly.
 14. (canceled)
 15. The method of claim 10, wherein the one or more sensor output signals comprise a signal indicative of a sensed weight-on-bit force occurring at the drill bit assembly.
 16. The method of claim 10, wherein one or more bottom hole devices included in the drill bit assembly comprise one or more of a bent motor, a thruster, a torque compliant tool, an adjustable stabilizer, and a friction reduction tool.
 17. The method of claim 10, wherein the controller is coupled to receive the sensor output signals from the one or more sensors located within the drill bit assembly over a wired communication link.
 18. A non-transitory computer readable medium storing computer readable instructions that when executed by a processor causes the processor to perform operations comprising: receiving, at the processor, one or more sensor output signals from one or more sensors located within a drill bit assembly of a bottom hole assembly positioned within a borehole wherein the drill bit assembly comprises a drill bit configured to advance a borehole through a formation, and one or more sensors located within the drill bit assembly and built into a drill bit shaft of the drill bit, the one or more sensors configured to sense one or more parameters indicative of a bending-on-bit direction and force level occurring at the drill bit during a drilling operation being performed by the drill bit assembly, and to provide the one or more sensor output signals based on the sensed one or more parameters; generating, by the processor and in real time, one or more output control signals based at least in part on the one or more sensor output signals from the one or more sensors, the one or more output control signals configured to control the operation of a steering system in order to correct and/or provide control parameter to the steering system in order to direct a drilling direction of the drilling operation being performed by the drill bit; and outputting, from the processor and in real time, the one or more output control signals to the steering system to control the operation of the steering system.
 19. The non-transitory computer readable medium of claim 18, wherein the processor is part of the bottom hole assembly.
 20. The non-transitory computer readable medium of claim 18, wherein the one or more sensor output signals comprise a first signal indicative of a sensed torque-on-bit force occurring at the drill bit assembly or a second signal indicative of a sensed weight-on-bit force occurring at the drill bit assembly. 